Hydrotreating process

ABSTRACT

A process for hydrotreating a hydrocarbon stream such as petroleum distillate and similar hydrocarbon materials by contacting said stream with hydrogen and a catalyst comprising a porous refractory inorganic oxide support and deposited thereon hydrogenation components comprising chromium, molybdenum and at least one Group VIII metal. This process enables improved removal of nitrogen and sulfur, particularly from gas oils.

This is a continuation of application Ser. No. 21,575, filed Nov. 19,1979 now U.S. Pat. No. 4,224,144.

BACKGROUND

This invention relates to catalytic hydrotreatment of petroleumdistillates and similar hydrocarbon materials. More particularly, thisinvention relates to the use of catalyst comprising a chromium componentwith molybdenum and Group VIII metal components, in such hydrotreatingprocesses.

In the petroleum refining industry, hydrotreating processes are in wideuse for effecting hydrodesulfurization and other upgrading treatment ofhydrocarbon stocks, typically carried out in the presence of a catalyst.Hydrofining refers generally to the treatment of solvents anddistillates with hydrogen and is typically a catalytic hydrogenation.Hydrofining is employed to remove sulfur, nitrogen and othernon-hydrocarbon components, as well as to improve the odor, color,stability, and other important quality characteristics. Typicalapplications range from relatively mild hydrosweetening operationscarried out at high space velocities, very low pressures andtemperatures, and minimal hydrogen consumption, to more severeoperations such as desulfurization and denitrification of heavy vacuumgas oils, decanted oils and lubricating oils. Sulfur and nitrogencompounds are often poisonous to the activity of catalysts employed whensuch carbonaceous feedstocks are further processed such as inhydrocracking and fluid catalytic cracking. When applied for processingcatalytic cracking feedstocks, hydrofining can significantly reducecatalyst coking and improve the quality of catalytic cracking stockresulting in increased gasoline yield as well as sulfur or nitrogenremoval.

Generally, the catalysts employed in hydrofining are comprised ofcomposites of Group VIB or Group VIII metal hydrogenating components, orboth, with an inorganic oxide base, or support, typically alumina. Forexample U.S. Pat. No. 3,245,919, Gring, et al., discloses hydrocarbonconversion processes that employ a catalyst containing a catalyticamount of a metal component selected from metals of Group VI and GroupVIII supported on alumina. The patent summarizes the prior art catalystmaterials which can include compounds of Groups VI and VIII metals suchas chromium, molybdenum, tungsten, iron, nickel cobalt, and the platinumgroup noble metals, or mixtures of two or more such compounds (column 6,lines 12 through 19), but does not disclose an example of chromium andmolybdenum in the same catalytic composition. Gring specificallydiscloses catalytic compositions in which only one of the two Group VImetals is employed and teaches the use of the catalytic compositioncontaining molybdenum with cobalt for desulfurization and the catalystcontaining chromium for dehydrogenation.

U.S. Pat. No. 3,114,701, Jacobson, et al., refers in general to priorart processes for hydrofining hydrocarbon oil by contact with variouscatalysts, generally comprising chromium and/or molybdenum oxidestogether with iron, cobalt, and/or nickel oxides on a porous oxidesupport, such as alumina or silica-alumina (column 1, lines 25 through20). However, this patent teaches a hydrodenitrification processemploying a catalyst containing large concentrations of nickel andmolybdenum on a predominantly alumina carrier; the patent does notprovide any examples using a specific catalytic composition comprisingchromium, molybdenum, and a Group VIII metal.

U.S. Pat. No. 2,577,823 (Stine, 1951) discloses that heavy hydrocarbonfractions, such as gas oil and reduced crude, can be hydrodesulfurizedover a catalyst consisting of chromium, molybdenum, and aluminum oxides,but this patent does not disclose or suggest that a Group VIII metalcomponent be incorporated in such catalyst.

U.S. Pat. No. 3,265,615 (Buss, 1966) discloses a method forhydrotreating hydrocarbon oil employing a catalyst comprising chromicsulfide and molybdenum sulfide prepared by the particular method of hisinvention. Buss discloses that in contrast to prior art catalystscontaining both a Group VI and a Group VIII component, the "absence of aGroup VIII component" in the catalyst prepared by his method permits anadvantage in the removal of nitrogen, as pointed out in column 5, lines35-50. Buss discloses a catalyst prepared by impregnating an aluminasupport with ammonium molybdate, then drying and calcining to produce amolybdenum oxide-alumina precursor which was then impregnated with anaqueous solution of chromic sulfate and dried overnight at lowtemperature; Buss teaches that the chromic sulfate must be subsequentlyreduced by treatment with hydrogen, and then the material is sulfided toproduce the chromium sulfide-molybdenum sulfide-alumina catalyst. Incontrast, the catalyst employed in the process of the present inventioncomprises a Group VIII metal component and the catalyst does not requirereduction of sulfate to sulfide in its preparation.

French Pat. No. 2,281,972 discloses the preparation of a catalystcomprising the oxides of cobalt, molybdenum, and/or nickel on a base ofboth alumina oxide and 3 to 15 wt.% chromium oxide and its use for therefining of hydrocarbon fractions such as the hydrodesulfurization offuel oils obtained by vacuum distillation or residual oils obtained byatmospheric distillation. The support base of this catalyst is composedof aluminum oxide and chromium oxide and is preferably prepared by thecoprecipitation of compounds of chromium and aluminum; in contrast thecatalyst employed in the process of the present invention comprises aninorganic oxide support, preferably alumina, upon which a compound ofchromium is deposed or impregnated.

Quick et al. in copending U.S. patent application Ser. No. 967,413,filed Dec. 7, 1978, which is incorporated herein by reference, disclosesa process for hydrotreating a heavy hydrocarbon stream containingmetals, asphaltenes, nitrogen compounds, and sulfur compounds, whichprocess comprises contacting said stream under suitable conditions andin the presence of hydrogen with a catalyst comprising a hydrogenatingcomponent selected from the group consisting of (1) molybdenum, chromiumand a small amount of cobalt, (2) their oxides, (3) their sulfides, and(4) mixtures thereof on a large-pore, catalytically active alumina.Quick et al. disclose that such process is particularly useful forhydrotreating heavy hydrocarbon streams such as petroleum residua, bothatmospheric resids and vacuum resids, tar sands oils, tar sands resids,and liquids obtained from coal. This application also suggest that suchprocess can be employed to satisfactorily hydrotreat petroleumhydrocarbon distillates, such as gas oils, cycle stocks, and furnaceoils; however, no example of the treatment of such distillate ispresented.

Typical commercial hydrofining catalysts are molybdena on alumina,cobalt molybdate on alumina, nickel molybdate on alumina or nickeltungstate on alumina. The specific catalyst used depends on theparticular application. Cobalt molbydate catalyst is often used whensulfur removal is the primary interest. The nickel catalysts findapplication in the treating of cracked stocks for olefin or aromaticsaturation. Sweetening to remove mercaptans is a preferred applicationfor molybdena catalysts. Denitrification is generally effected by theuse of a supported sulfided catalyst containing nickel and molybdenum.

The primary objective of the present invention is to achieve improvedhydrotreating of petroleum distillates and similar materials. Anadditional objective is to provide improved catalyst for use in suchhydrotreating processes.

We have found that the objects of this invention can be achieved bycontacting hydrocarbon streams such as petroleum distillates and similarmaterials with hydrogen and a catalyst comprising chromium, molybdenum,and at least one Group VIII metal hydrogenation components deposited ona porous refractory inorganic oxide support, which is effective in theremoval of both sulfur and nitrogen from such hydrocarbon streams, incontrast to catalyst which does not contain chromium with Group VIIImetal.

Typical feedstocks that can be treated satisfactorily by the process ofthe present invention generally comprise distillates from petroleum andtar sands as well as similar materials such as shale oil and fractionsthereof. Generally, these hydrocarbon streams are substantially freefrom asphaltenic materials and will usually contain only trace amountsof metals such as nickel and vanadium, thus permitting sulfur andnitrogen to be removed more readily than such removal from heavyhydrocarbon streams such as petroleum resid and whole tar sands oil.While lighter distillates such as naphthas, kerosene and dieselfractions can be treated by the process of the present invention,particularly effective removal of sulfur and nitrogen from heavierdistillate such as gas oils, decanted oils, lubricating oils and recyclestreams can be obtained employing the process of this invention in moresevere operation. Typical heavy gas oil streams are obtained by vacuumdistillation of petroleum as well as gas oils obtained by coking reducedcrude, vacuum resid and similar materials such as tar sands oil. Inaddition to removing sulfur and nitrogen, treatment of gas oil andsimilar heavy distillate streams at high temperature in the process ofthis invention can achieve substantial hydrocracking of heavy componentsin such feedstocks.

The hydrogenation components of the catalyst employed in the process ofthe present invention comprise chromium, molybdenum, and at least oneGroup VIII metal, preferably cobalt; as used herein, the term"hydrogenation components" is meant to include Group VIII metal,molybdenum, and chromium present in the catalyst in the elemental form,as oxides of the metals, as sulfides of the metals, or mixtures thereof.Group VIII metals selected from iron, cobalt, nickel, ruthenium,rhodium, platinum, palladium, osmium, and iridium, can be employed as ahydrogenation component and cobalt is the preferred Group VIII metalcomponent. Suitably, the Group VIII metal, exemplified by cobalt, ispresent in the catalyst in the range of about 0.1 wt.% to about 5 wt.%,calculated as the oxide of the metal and based upon the total catalystweight; the chromium is present in an amount within the range of about 5wt.% to about 30 wt.%, calculated as Cr₂ O₃ and based upon the totalcatalyst weight, and molybdenum is present in an amount within the rangeof about 5 wt.% to about 20 wt.%, calculated as MoO₃ and based upon thetotal catalyst weight. Preferably, the cobalt is present in an amountwithin the range of about 0.5 wt.% to about 2.5 wt.%, calculated as CoOand based upon the total catalyst weight, the chromium is present in anamount within the range of about 7-20 wt.%, calculated as Cr₂ O₃ andbased upon the total catalyst weight, and the molybdenum is present inan amount within the range of about 7-15 wt.%, calculated as MoO₃ andbased upon the total catalyst weight, such components being deposited ona catalytically active alumina support. Chromium and molybdenum contentsof the catalyst in excess of these preferred ranges add expense andappear to provide no appreciable gain in catalyst activity, while levelsof chromium and molybdenum less than these preferred ranges appear toprovide decreased catalyst activity; a cobalt content in excess of thepreferred range appears to cause accelerated deactivation of thecatalyst, yet the cobalt content should not be less than the preferredrange in order to provide sufficient activity for commercial use.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 depicts comparative desulfurization performance of commercialcatalyst and a catalyst employed in the process of this invention.

FIG. 2 depicts comparative denitrogenation performance of commercialcatalysts and a catalyst employed in the process of this invention.

FIG. 3 presents conversion of a tar sands oil distillate into lighterproducts in an embodiment of the process of this invention.

In preparing the catalyst employed in the process of this invention,chromium, molybdenum, and Group VIII metal hydrogenation components canbe deposited upon a porous refractory inorganic oxide support or carriersuch as alumina, silica-alumina, silica, magnesia, zirconia, and similarmaterials, for example by impregnation of the support with compounds ofthe metals. Desirably, after the hydrogenation metals are deposited onthe support the material is formed into pellets, or extruded, and thencalcined. The catalyst can be prepared by the typical commercial methodof impregnating the hydrogenation components upon high surface arearefractory inorganic oxide support with one or more solutions, usuallyaqueous, of heat-decomposable compounds of the appropriate metals. Theimpregnation can be a co-impregnation when a single solution isemployed. Alternatively, sequential impregnation of the metals from twoor more solutions can be employed. Generally, the impregnated support isdried at a temperature of at least 250° F. (121° C.) for a period of atleast one hour and calcined in air at a temperature of at least 800° F.(427° C.), and preferably at least 1,000° F. (538° C.), for at least twohours.

Preferably, the catalyst used in the process of this invention isprepared by impregnating an alumina support with the aqueous solution orsolutions containing the heat-decomposable salts of chromium,molybdenum, and cobalt. Suitable high surface area alumina is preferablyemployed as the catalyst support; alumina is a preferred support basedupon superior stability and activity in general desulfurization anddenitrogenation service. The alumina should have a pore volume that isin excess of 0.4 cc/gm, a surface area that is in excess of 150m^(2/gm), and an average pore diameter that is greater than about 60Angstroms. Such alumina is commercially available, for example, fromAmerican Cyanamid Company, and from Continental Oil Company under thetradename "CATAPAL." Generally, such alumina is commercially availablein hydrate form such as the alphamonohydrate, boehmite, or in calcinedform such as gamma-alumina; other aluminas such as eta-alumina and itshydrate precursors can also be employed for the catalyst support.

The finished catalyst that is employed in the process of the presentinvention should have a pore volume within the range of about 0.4 cc/gmto about 0.8 cc/gm, a surface area within the range of about 150 m² /gmto about 300 m² /gm, and an average pore diameter within the range ofabout 60 A to about 200 A. Preferably, the catalyst has a pore volumewithin the range of about 0.5 cc/gm to about 0.7 cc/gm, a surface areawithin the range of about 150 m² /gm to about 250 m² /gm, and an averagepore diameter within the range of about 70 A. to about 150 A. Thecatalyst should have about 0% to about 50% of its pore volume in poreshaving diameters that are smaller than 50 A, about 30% to about 80% ofits pore volume in pores having diameters of about 50 A to about 100 A,about 0% to about 50% of its pore volume in pores having diameters ofabout 100 A to about 150 A, and about 0% to about 20% of its pore volumein pores that are larger than 150 A. Best results have been obtainedwith catalyst having a pore volume distribution summarized as follows:

    ______________________________________                                        Pore Diameters. A                                                                              % of Pore Volume                                             ______________________________________                                        0-50             20-50                                                        50-100           30-70                                                        100-150           0-20                                                        150 +             0-10                                                        ______________________________________                                    

Values specified for catalyst surface area are obtained by the BETnitrogen adsorption method. Values specified for pore volume are alsoobtained by nitrogen adsorption and specified average pore diameters arethose calculated by means of the expression: ##EQU1## whereinA.P.D.=average pore diameter in A,

P.V.=pore volume in cc/gm, and

S.A.=surface area in m² /gm

Pore size distributions are obtained by a Digisorb 2500 instrumentemploying nitrogen desorption techniques.

The catalyst used in the process of this invention can be employed inthe form of a fixed-bed or an ebullated-bed of particles. In the case ofa fixed-bed catalyst particle size should be about 1/32-1/8 in.(0.08-0.32 cm) effective diameter.

The conditions employed in operation of the process of the presentinvention will vary with the particular hydrocarbon stream beingtreated, with mild conditions employed in the hydrotreatment of lightdistillate such as naphtha and kerosene, typically 450° to 600° F. (232°to 316° C.) and about 100 to 600 psi (690 to 4137 kPa) hydrogen partialpressure. Heavier materials such as gas oil and similar hydrocarbonstreams can be treated under conditions of about 500 to about 2,500 psi(3.45 to 17.24 MPa) hydrogen partial pressure and an average catalystbed temperature within the range of about, 600° F. (315° C.) to about820° F. (438° C.) with an LHSV (liquid hourly space velocity) within therange of about 0.5-10 volumes of hydrocarbon per hour per volume ofcatalyst and a hydrogen recycle rate or hydrogen addition rate withinthe range of about 1,000 SCFB to about 10,000 SCFB (178 to 1780 m³ /m³).Best results in the removal of sulfur and nitrogen from gas oils havebeen obtained under conditions of about 1,000 psi to about 2,000 psi(6.9-13.8 MPa) hydrogen partial pressure and average catalyst bedtemperatures within the range of about 700° to about 820° F. (371° to438° C.) at an LHSV of about 1-8 volumes of hydrocarbon per hour pervolume of catalyst and a hydrogen recycle rate or hydrogen addition ratewithin the range of about 1000 SCFB to about 6000 SCFB (178 to 1069 m³/m³).

The following examples are illustrative of this invention but do notindicate limitation upon the scope of the claims.

EXAMPLE 1

Catalyst A, representing an embodiment of the catalyst employed in theprocess of this invention, was prepared to contain approximately 10 wt.%Cr₂ O₃, 8 wt.% MoO₃, and 1.5 wt.% CoO, with properties fully specifiedin Table II. This catalyst was prepared with a gamma-alumina support inthe form of 1/32" (0.08 cm) extrudates, commercially obtainable fromAmerican Cyanamid Company, having a surface area of about 204 m² /gm, anaverage pore diameter of about 151 Angstroms, and a pore volume of about0.77 cc/gm, wherein the pore volume comprised the following exemplarydistribution:

    ______________________________________                                        Pore Diameters, A                                                                              % of Pore Volume                                             ______________________________________                                        0-50             1.5                                                          50-100           65.3                                                         100-150          32.2                                                         150+             1.0                                                          ______________________________________                                    

The gamma alumina extrudate support was impregnated with a mixture oftwo solutions prepared as follows:

a. To an agitated vessel containing 1518 gms. of deionized water, 1518gms. of Chromic Acid (CRO₃) was added. After dissolution of the ChromicAcid, 966 gms. of Cobalt Nitrate solution (concentration 15.5% CoO) wasadded.

b. To an agitated vessel containing 3275 gms. of warm (ca. 65° C.)deionized water, 1356 gms. of Ammonium Dimolybdate (85% MoO₃) was added.

c. Prior to impregnation, solution (b) was added to solution (a) withmixing. Specific gravity of the complex solution at 48° C. was measuredat 1.33 by hydrometer.

Impregnation

Twenty pounds (9.06 kg) of the blank gamma-alumina extrudates werecharged to a baffled rotating drum. The complex solution of (2) above(cooled to ambient temperature) was distributed onto the tumbling bed ofextrudates over a period of ten minutes and mixing was continued untilthe extrudates were free flowing.

Finishing

The wet impregnated extrudates, after aging for 90 minutes, were chargedto an indirect fired batch rotary calciner which had been preheated to600° F. (315° C.). Air at 1 CFM (28.3 l/min.) was blown across the bedof extrudates to sweep out volatiles. Bed temperature was brought to1000° F. and held at this temperature for one hour, after which thecalcined product was discharged.

Heavy vacuum gas oil, with properties presented in Table I, washydrotreated in an embodiment of the process of this invention, withCatalyst A containing approximately 10 wt.% Cr₂ O₃, 8 wt.% MoO, and 1.5wt.% CoO on a high surface area alumina support, with catalystproperties more fully specified in Table II.

Prior to its use, the catalyst was calcined in still air at atemperature of about 1,000° F. (537° C.) for one hour and cooled in adesiccator. Before establishing hydrocarbon flow, the catalyst wassubjected to a conventional presulfiding with a gas mixture containingabout 8 mole % hydrogen sulfide in hydrogen at a pressure ofapproximately 500 psig (3.45 MPa), with the temperature slowly raisedfrom 300° F. (148° C.) to about 700° F. (371° C.).

The run was carried out in a bench-scale test unit having automaticcontrols for pressure, flow of reactants, and temperature. The reactorwas made from 3/8-inch (0.95 cm) inside diameter stainless steel,heavy-walled tubing. A 1/8-inch (0.32 cm) outside diameter thermowellextended up through the center of the reactor. The reactor was heated byan electrically-heated steel block. The hydrocarbon feedstock was fed tothe unit by means of a Ruska pump, a positive-displacement pump. The14-to-20-mesh catalyst material was supported on 8-to-10-mesh alundumparticles. Approximately 15 cubic centimeters of the catalyst wasemployed. This amount of catalyst provided a catalyst bed length ofabout 10 inches. A 10-inch layer of 8-to-10-mesh alundum particles wasplaced over the catalyst bed in the reactor. The catalyst was placed inthe annular space between the thermowell and the internal wall of the3/8-inch (0.95 cm) inside-diameter reactor.

Selected samples from the run were obtained from the product receiverand were analyzed for pertinent information. Data obtained from samplestaken during the indicated day of operation conducted at an LHSV of 1.0volume of hydrocarbon per hour per volume of catalyst, a temperature of800° F. (427° C.), and a pressure of 1400 psig (9.65 MPa) with 2000 SCFB(356 m³ /m³), are presented hereinbelow as Run 1 in Table IV and in FIG.2.

EXAMPLE 2

For comparison, the heavy vacuum gas oil described in Example 1 washydrotreated using a commercial hydrodesulfurization catalyst obtainedfrom the Nalco Chemical Company, designated Nalco 477, containingapproximately 3.5 wt.% CoO and 15 wt.% MoO₃ on an alumina support, withcatalyst properties more fully specified in Table I as Catalyst B. Thisoperation was conducted in the same bench-scale equipment withconditions and catalyst pretreatment as described in Example 1. Theresults of this operation are presented as Run 2 in Table IV and inFIGS. 1 and 2.

EXAMPLE 3

For comparison, the heavy vacuum gas oil previously described in Example1 was hydrotreated using a commercial hydrodenitrification catalystobtained from Nalco Chemical Company, designated NM506, containingapproximately 7 wt.% NiO and 25 wt.% MoO₃ on an alumina support, withproperties more fully specified in Table II, as Catalyst C. Thisoperation was carried out in the same bench-scale equipment withconditions and catalyst pretreatment as described in Example 1. Resultsof this operation are presented as Run 3 in Table IV and in FIGS. 1 and2.

EXAMPLE 4

Catalyst D, representing an embodiment of the catalyst employed in theprocess of the present invention, was prepared to contain approximatelythe same levels of hydrogenation components as those contained inCatalyst A; however, Catalyst D was prepared using a successiveimpregnation technique as follows: the catalyst was prepared with agamma-alumina support in the form of 1/32" (0.08 cm) extrudates,commercially obtained from the American Cyanamid Company, having asurface area of approximately 192 m² /gm, an average pore diameter ofabout 159 A and a pore volume of about 0.76 cc/gm, wherein the porevolume comprised the following exemplary distribution:

    ______________________________________                                        Pore Diameters, A                                                                              % of Pore Volume                                             ______________________________________                                        0-50             1.3                                                          50-100           53.8                                                         100-150          43.6                                                         150+             1.3                                                          ______________________________________                                    

A sample of this support was calcined at approximately 1,000° F. (537°C.) for about one hour. 162.5 gm of the calcined support was impregnatedwith 220 ml of distilled water containing 34.2 gm of ammonium dichromateand 25.3 gm ammonium molybdate. The resulting mixture was left to standovernight. This mixture was dried subsequently under a heat lamp instatic air for a period of about 2 hours to remove the excess water. Thedried material was then calcined in static air at a temperature ofapproximately 1,000° F. (537° C.) for a period of about 2 hours. 99.2 gmof this calcined material was then impregnated with a solutioncontaining 5.0 gm of Co(MO₃)₂.6H₂ O in 100 ml of distilled water andthis mixture was allowed to stand overnight. The material was then driedunder a heat lamp in static air for a period of about 2 hours and thedried material was then calcined in static air at a temperature of1,000° F. (537° C.) for a period of about 2 hours.

The finished Catalyst D was analyzed to contain 1.5 wt.% CoO, 8.4 wt.%MoO₃, and 9.5 wt.% Cr₂ O₃. For comparison, Catalyst D was tested usingthe same feedstock, equipment, catalyst pretreatment, and conditions ofoperation as described in Example 1. The results of this operation arepresented as Run 4 in Table IV.

EXAMPLE 5

Catalyst E, representing a preferred embodiment of the catalyst employedin the process of the present invention, was prepared to containapproximately the same levels of hydrogenation components as thosecontained in Catalyst A; however, Catalyst E was prepared on a differentsupport and using a successive impregnation technique as follows: thecatalyst was prepared with a gamma-alumina support in the form of 1/16"(0.16 cm) extrudates, commercially obtained from the Continental OilCompany under the tradename "CATAPAL," having a surface area ofapproximately 263 m² /gm, an average pore diameter of about 87 A and apore volume of about 0.57 cc/gm, wherein the pore volume comprised thefollowing exemplary distribution:

    ______________________________________                                        Pore Diameters, A                                                                              % of Pore Volume                                             ______________________________________                                        0-50             43.9                                                         50-100           53.3                                                         100-150          1.1                                                          150+             1.7                                                          ______________________________________                                    

A sample of this support was calcined at approximately 1,000° F. (537°C.) for about one hour. 136.6 gm of the calcined support was impregnatedwith 100 ml of distilled water containing 28.3 gm of ammonium dichromateand 21.0 gm ammonium molybdate. The resulting mixture was left to standovernight. This mixture was dried subsequently under a heat lamp instatic air for a period of about 2 hours to remove the excess water. Thedried material was then calcined in static air at a temperature ofapproximately 1,000° F. (537° C.) for a period of about 2 hours. 82.0 gmof this calcined material was then impregnated with a solutioncontaining 4.1 gm of Co(NO₃)₂.6H₂ O in 50 ml of distilled water and thismixture was allowed to stand overnight. The material was then driedunder a heat lamp in static air for a period of about 2 hours and thedried material was then calcined in static air at a temperature of1,000° F. (537° C.) for a period of about 2 hours.

The finished Catalyst E was analyzed to contain 1.3 wt.% CoO, 9.4 wt.%MoO₃, and 11.0 wt.% Cr₂ O₃. For comparison, Catalyst E was tested usingthe same feedstock, equipment, catalyst pretreatment, and conditions ofoperation as described in Example 1. The results of this operation arepresented as Run 5 in Table IV.

EXAMPLE 6

Catalyst F was prepared by reimpregnating Catalyst A with sufficientcobalt nitrate to provide higher cobalt level indicated by analysis ofthe finished catalyst to be 3.3 wt.% CoO, 8.4 wt.% MoO₃, and 9.9 wt.%Cr₂ O₃. For comparison, Catalyst F was tested using the same feedstock,equipment, catalyst pretreatment, and conditions of operation asdescribed in Example 1. The results of this operation are presented asRun 6 in Table V.

EXAMPLE 7

Catalysts G and H were prepared with the same support and in the samemanner as the preparation of Catalyst D with the exception thatappropriate adjustments in the amount of ammonium dichromate used weremade in order to prepare Catalyst G with lower chromium content thanCatalyst A and to prepare Catalyst H with higher chromium content thanCatalyst A. Catalyst G contained approximately 5 wt.% Cr₂ O₃, andCatalyst H contained approximately 20 wt.% Cr₂ O₃ ; actual analyses ofCatalysts G and H are presented in Table III. Tests of Catalysts G and Hwere carried out using the same feedstock, equipment, catalystpretreatment, and conditions of operation as described in Example 1. Theresults of these operations are presented as Runs 7 and 8 in Table V.

EXAMPLE 8

Catalyst I was prepared with similar support and in the same manner asthe preparation of Catalyst D with the exception that the finishedcatalyst contained approximately 3 wt.% CoO, 8 wt.% Cr₂ O₃, and 8 wt.%MoO₃. This catalyst was employed in the hydrotreatment of the wholeshale oil feedstock described in Table I using similar equipment andcatalyst pretreatment as described in Example 1. The conditions andresults of this operation are presented in Table VIII.

                  TABLE I                                                         ______________________________________                                        FEEDSTOCK PROPERTIES                                                                       A       B                                                                     Heavy   Tar Sands C                                                           Vacuum  Coker     Whole                                                       Gas Oil Gas Oil   Shale Oil                                      ______________________________________                                        Gravity, °API                                                                         19.7      8.0       21.0                                       Nitrogen, Wt. %                                                                              0.149     .374      1.88                                       Sulfur, Wt. %  2.87      4.6       0.78                                       Carbon, Wt. %  85.18     85.14     84.89                                      Hydrogen, Wt. %                                                                              11.80     9.92      9.92                                       Oxygen, Wt. %  --        --        1.4                                        ASTM DISTILLATION                                                             IBP °F. 577       438       116                                         5% °F. 670       621       361                                        10% °F. 713       669       426                                        20% °F. 766       727       526                                        30% °F. 802       768       614                                        50% °F. 859       835       773                                        70% °F. 914       904       917                                        80% °F. 946       947       1000                                       ______________________________________                                    

                  TABLE II                                                        ______________________________________                                        CATALYST PROPERTIES                                                           CATALYST          A      B      C    D    E                                   ______________________________________                                        HYDROGENATION                                                                 COMPONENT, WT. %                                                              CoO               1.5    3.4    --   1.5  1.3                                 Cr.sub.2 O.sub.3  10.1   --     --   9.5  11.0                                MoO.sub.3         8.6    15.3   24.8 8.4  9.4                                 NiO               --     --     6.9  --   --                                  PHYSICAL PROPERTIES                                                           SURFACE AREA, m.sup.2 /gm                                                                       179    208    219  170  226                                 PORE VOLUME, cc/gm                                                                              0.58   0.58   0.40 0.57 0.44                                AVG. PORE DIAM., A                                                                              130    112    73   135  78                                  % OF PORE VOLUME IN:                                                           0-50 A PORES     4.9    7.5    12.1 4.7  38.0                                 50-100 A PORES   75.0   64.4   84.4 58.0 59.5                                100-150 A PORES   19.6   16.2   0.8  35.8 1.2                                 150+ A PORES      0.5    11.9   2.1  1.5  1.3                                 ______________________________________                                    

                  TABLE III                                                       ______________________________________                                        CATALYST PROPERTIES                                                           CATALYST         A       F       G     H                                      ______________________________________                                        HYDROGENATION                                                                 COMPONENT, WT. %                                                              CoO              1.5     3.3     1.4   1.2                                    Cr.sub.2 O.sub.3 10.1    9.9     4.7   18.1                                   MoO.sub.3        8.6     8.4     9.5   7.9                                    NiO              --      --      --    --                                     PHYSICAL PROPERTIES                                                           SURFACE AREA, m.sup.2 /gm                                                                      179     179     185   157                                    PORE VOLUME, cc/gm                                                                             0.58    0.56    0.63  0.50                                   AVG. PORE DIAM., A                                                                             130     125     135   128                                    % OF PORE VOLUME IN:                                                           0-50 A PORES    4.9     5.4     4.0   7.2                                     50-100 A PORES  75.0    69.5    61.8  59.7                                   100-150 A PORES  19.6    24.0    33.0  28.4                                   150+ A PORES     0.5     1.1     1.2   4.7                                    ______________________________________                                    

As Table IV and FIGS. 1 and 2 demonstrate, the catalyst employed in theprocess of this invention, represented by Catalyst A, while indicatingan initial period of activation for sulfur removal is clearly superiorto commercial Catalysts B and C in sulfur and nitrogen removalperformance. The catalysts employed in the process of this invention aresurprisingly resistant to deactivation under the demonstrated relativelysevere conditions of operation.

                  TABLE IV                                                        ______________________________________                                        RUN NO.          1      2      3    4    5                                    CATALYST         A      B      C    D    E                                    ______________________________________                                        OPERATING CONDITIONS                                                          TEMPERATURE, °F.                                                                         800    800    800  800  800                                 PRESSURE, psig   1400   1400   1400 1400 1400                                 LHSV              1.0    1.0    1.0  1.0  1.0                                 HYDROGEN RATE,                                                                SCFB             2000   2000   2000 2000 2000                                 SAMPLE FROM DAY   16     16     16   12   20                                  PRODUCT                                                                       % SULFUR REMOVAL 99.0   92.0   91.2 98.6 99.7                                 % NITROGEN REMOVAL                                                                             88.0   79.8   53.5 84.8 96.1                                 LIQUID GRAVITY, °API                                                                    32.3   31.3   31.9 32.9 33.4                                 ______________________________________                                    

Table V demonstrates that the cobalt oxide level of about 3 wt.% inCatalyst F appears to produce a reduction in sulfur and nitrogen removalperformance when compared to the performance of Catalyst A having alower cobalt oxide content. The performance of Catalyst G which haslower chromium content than Catalyst A resulted in decreased sulfur andnitrogen removal by comparison. The performance of Catalyst H indicatesthat a higher level of chromium oxide at about 20 wt.% can provideapproximately the same performance as Catalyst A having the lower levelof about 10 wt.% Cr₂ O₃.

                  TABLE V                                                         ______________________________________                                        RUN NO.          1       6       7     8                                      CATALYST         A       F       G     H                                      ______________________________________                                        OPERATING CONDITIONS                                                          TEMPERATURE, °F.                                                                         800     800     800   800                                   PRESSURE, psig   1400    1400    1400  1400                                   LHSV              1.0     1.0     1.0   1.0                                   HYDROGEN RATE,                                                                SCFB             2000    2000    2000  2000                                   SAMPLE FROM DAY    6       6       6     6                                    PRODUCT                                                                       % SULFUR REMOVAL 99.0    95.5    93.8  99.3                                   % NITROGEN REMOVAL                                                                             89      48.0    54.6  85.4                                   LIQUID GRAVITY, °API                                                                    32.3    32.5    31.1  32.5                                   ______________________________________                                    

Table VI presents results treating Feedstock A, showing variation inspace velocity and indicating that Catalyst E produces particularlyeffective sulfur and nitrogen removal even under relatively highhydrocarbon flow rates corresponding to space velocity of about 3 LHSVand 6 LHSV.

                  TABLE VI                                                        ______________________________________                                        CATALYST         A      A      E    E    E                                    ______________________________________                                        OPERATING CONDITIONS                                                          TEMPERATURE, °F.                                                                         800    800    800  800  800                                 PRESSURE, psig   1400   1400   1400 1400 1400                                 LHSV              1     2      1    3    6                                    HYDROGEN RATE,                                                                SCFB             2000   2000   2000 2000 2000                                 SAMPLE FROM DAY  10     8      3    6    8                                    PRODUCT                                                                       % SULFUR REMOVAL 99.5   96.9   99.7 98.6 92.3                                 % NITROGEN REMOVAL                                                                             89.1   69     38.0 45.0 --                                   LIQUID GRAVITY, °API                                                                    32.9   30.0   33.8 29.8 28.1                                 ______________________________________                                    

Table VII and FIG. 3 presents results showing the conversion ofFeedstock B, a gas oil fraction from coked tar sands oil, using CatalystA in an embodiment of the process of this invention. These resultsdemonstrate that very little light-end gases were produced when theheavy gas oil was hydrocracked to yield predominantly distillate rangeproduct with substantial removal of sulfur and nitrogen as indicated.

                  TABLE VII                                                       ______________________________________                                        DAYS ON OIL       5      7      8    16   18                                  ______________________________________                                        OPERATING CONDITIONS                                                          TEMPERATURE, °F.                                                                         780    780    780  780  780                                 PRESSURE, psig    1800   1800   1800 1400 1000                                LHSV              0.5    0.25   1.0  0.5  0.5                                 HYDROGEN RATE,                                                                SCFB              1810   2040   1500 1275 1030                                PRODUCT                                                                       % SULFUR REMOVAL  99.6   96.6   98.3 99.3 96.8                                % NITROGEN REMOVAL                                                                              97.6   98.9   84.0 92.5 33.9                                % CONVERSION OF 650° F.                                                + MATERIAL        60     67     45   49   47                                  LIQUID GRAVITY, °API                                                                     29.1   31.1   25.0 27.4 26.3                                C.sub.1 -C.sub.4 WT. %                                                                          5.1    5.0    4.5  3.0  3.6                                 ______________________________________                                    

Table VIII presents results showing the hydrotreatment of Feedstock C, awhole shale oil, using Catalyst I described in Example 8. These resultsdemonstrate that the process of this invention can substantially removeeven the very high nitrogen content from a shale oil.

                  TABLE VIII                                                      ______________________________________                                        DAYS ON OIL      3       6       16    27                                     ______________________________________                                        OPERATING CONDITIONS                                                          PRESSURE, psig   1700    1700    1700  1700                                   LHSV             1.0     0.5     1.0   2.0                                    TEMPERATURE, °F.                                                                        730     730     760   780                                    HYDROGEN RATE,                                                                SCFB                                                                          PRODUCT                                                                       LIQUID GRAVITY, °API                                                                    30.8    33.7    33.5  32.9                                   % NITROGEN REMOVAL                                                                             57.8    77.5    68.5  51.3                                   % SULFUR REMOVAL 93.7    96.2    97.5  88.6                                   ______________________________________                                    

Overall, the catalyst employed in the process of this invention, bestrepresented by Catalyst E, enables improved removal of sulfur andnitrogen in the hydrotreatment of petroleum distillates and similarhydrocarbon materials.

We claim:
 1. A process for hydrotreating a hydrocarbon stream whichprocess comprises contacting a hydrocarbon stream comprising a streamselected from petroleum distillate, tar sands distillate, and shale oil,with hydrogen and a catalyst comprising a porous refractory inorganicoxide support and deposited thereon hydrogenation components comprisingchromium, molybdenum and at least one Group VIII metal.
 2. The processof claim 1 wherein said catalyst support comprises silica-alumina. 3.The process of claim 1 wherein said catalyst support comprises silica.4. The process of claim 1 wherein said Group VIII metal comprisescobalt.
 5. The process of claim 4 wherein said catalyst compriseschromium, molybdenum and cobalt hydrogenation components in at least oneform selected from the group consisting of the elemental form, theoxide, and the sulfide.
 6. The process of claim 5 wherein said chromiumis present in an amount within the range of about 5 wt.% to about 30wt.%, calculated as Cr₂ O₃ and based upon the total catalyst weight,said molybdenum is present in an amount within the range of about 5 wt.%to about 20 wt.%, calculated as MoO₃ and based upon the total catalystweight, and said cobalt is present in an amount within the range ofabout 0.1 wt.% to about 5 wt.%, calculated as CoO and based upon thetotal catalyst weight.
 7. The process of claim 5 wherein said chromiumis present in an amount within the range of about 7 wt.% to about 20wt.%, calculated as Cr₂ O₃ and based upon the total catalyst weight,said molybdenum is present in an amount within the range of about 7 wt.%to about 15 wt.%, calculated as MoO₃ and based upon the total catalystweight, and said cobalt is present in an amount within the range ofabout 0.5 wt.% to about 2.5 wt.%, calculated as CoO and based upon thetotal catalyst weight.
 8. The process of claim 1 wherein said catalystis prepared by impregnating said support with aqueous solution ofheat-decomposable compounds of said hydrogenation metals.
 9. The processof claim 1, said catalyst having a pore volume within the range of about0.4 cc/gm to 0.8 cc/gm, a surface area within the range of about 150 m²/gm to about 300 m² /gm, and an average pore diameter within the rangeof about 60 A to about 200 A.
 10. The process of claim 1 wherein saidprocess is carried out under conditions comprising an average catalystbed temperature within the range of about 700° F. (371° C.) to about820° F. (438° C.) and hydrogen partial pressure in the range of about500 psi to about 2,500 psi (3.45 to 17.24 MPa).
 11. The process of claim1 wherein said hydrocarbon stream comprises petroleum gas oil.
 12. Theprocess of claim 1 wherein said hydrocarbon stream comprises tar sandsgas oil.
 13. A process for hydrotreating a hydrocarbon stream whichprocess comprises contacting a hydrocarbon stream comprising a streamselected from petroleum distillate, tar sands distillate, and shale oil,with hydrogen and a catalyst comprising alumina support and depositedthereon hydrogenation components comprising chromium, molybdenum and atleast one Group VIII metal.
 14. The process of claim 13 wherein saidGroup VIII metal comprises cobalt.
 15. The process of claim 14 whereinsaid catalyst comprises chromium, molybdenum and cobalt hydrogenationcomponents in at least one form selected from the group consisting ofthe elemental form, the oxide, and the sulfide.
 16. The process of claim15 wherein said chromium is present in an amount within the range ofabout 5 wt.% to about 30 wt.%, calculated as Cr₂ O₃ and based upon thetotal catalyst weight, said molybdenum is present in an amount withinthe range of about 5 wt.% to about 20 wt.%, calculated as MoO₃ and basedupon the total catalyst weight, and said cobalt is present in an amountwithin the range of about 0.1 wt.% to about 5 wt.%, calculated as CoOand based upon the total catalyst weight.
 17. The process of claim 14wherein said chromium is present in an amount within the range of about7 wt.% to about 20 wt.%, calculated as Cr₂ O₃ and based upon the totalcatalyst weight, said molybdenum is present in an amount within therange of about 7 wt.% to about 15 wt.%, calculated as MoO₃ and basedupon the total catalyst weight, and said cobalt is present in an amountwithin the range of about 0.5 wt.% to about 2.5 wt.%, calculated as CoOand based upon the total catalyst weight.
 18. The process of claim 13wherein said hydrocarbon stream comprises petroleum distillate.
 19. Theprocess of claim 13 wherein said hydrocarbon stream comprises tar sandsdistillate.
 20. The process of claim 13 wherein said hydrocarbon streamcomprises shale oil.
 21. The process of claim 14, said catalyst having apore volume within the range of about 0.4 cc/gm to 0.8 cc/gm, a surfacearea within the range of about 150 m² /gm to about 300 m² /gm, and anaverage pore diameter within the range of about 60 A to about 200 A. 22.The process of claim 21 wherein said hydrocarbon stream comprisespetroleum gas oil.
 23. The process of claim 21 wherein said hydrocarbonstream comprises tar sands gas oil.
 24. The process of claim 21 whereinsaid hydrocarbon stream comprises shale oil.
 25. The process of claim 13wherein said catalyst is prepared by impregnating said support withaqueous solution of heat-decomposable compounds of said hydrogenationmetals.
 26. The process of claim 17, said catalyst having a pore volumewithin the range of about 0.4 cc/gm to 0.8 cc/gm, a surface area withinthe range of about 150 m² /gm to about 300 m² /gm, and an average porediameter within the range of about 60 A to about 200 A.
 27. The processof claim 17 wherein said process is carried out under conditionscomprising an average catalyst bed temperature within the range of about700° F. (371° C.) to about 820° F. (438° C.) and hydrogen partialpressure in the range of about 500 psi to about 2,500 psi (3.45 to 17.24MPa).
 28. The process of claim 27 wherein said hydrocarbon streamcomprises petroleum gas oil.
 29. The process of claim 27 wherein saidhydrocarbon stream comprises tar sands gas oil.
 30. The process of claim27 wherein said hydrocarbon stream comprises shale oil.